Full Year 2026 Amplitude Energy Ltd Earnings Call

August 17, 2026

Speaker #1: Good day, and welcome to the Amplitude Energy Limited FY26 Full Year Results webcast. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.

Operator 2: Good day, and welcome to the Amplitude Energy Limited FY2026 full year results webcast. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, followed by the number one on your telephone keypad. If you would like to withdraw your question, please press star one again. For operator assistance throughout the call, please press star zero. I would like to advise all participants that this call is being recorded. Thank you. I would now like to welcome Jane Norman, Managing Director and Chief Executive Officer, to begin the conference. Jane, over to you.

Operator: Good day, and welcome to the Amplitude Energy Limited FY 2026 Full Year Results Webcast. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, followed by the number one on your telephone keypad. If you would like to withdraw your question, please press star one again. For operator assistance throughout the call, please press star zero. I would like to advise all participants that this call is being recorded. Thank you. I would now like to welcome Jane Norman, Managing Director and Chief Executive Officer, to begin the conference. Jane, over to you.

Speaker #1: If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, please press star one again.

Speaker #1: For operator assistance throughout the call, please press star zero. And finally, I would like to advise all participants that this call is being recorded.

Speaker #1: Thank you. I'd now like to welcome Jane Norman, Managing Director and Chief Executive Officer, to begin the conference. Jane, over to you.

Speaker #2: Thank you . Good morning , and thank you for joining us for Amplitude Energy FY 26 full year results . This is Jane Norman , and I'm joined today by Chief Financial Officer Ian Bucknell and Chief Operating Officer Chad Wilson Today's presentation and announcement were released to the ASX this morning and are available on the Amplitude Energy website .

Jane Norman: Thank you. Good morning, and thank you for joining us for Amplitude Energy's FY2026 full year results. This is Jane Norman, and I am joined today by Chief Financial Officer, Ian Bucknell, and Chief Operating Officer, Chad Wilson. Today's presentation and announcement were released to the ASX this morning and are available on the Amplitude Energy website. The webcast is being recorded and will be available on our website later today. Please note the disclaimer on slide 2 before moving to slide 3. I will start today by reflecting on our accomplishments through FY2026 before moving to an in-depth review of the financial year in the next section. FY2026 was another strong year of delivery for Amplitude Energy. We achieved record production and record financial results. Performance was supported by continued improvement at Orbost, resilient pricing from our contracted sales portfolio, and active gas marketing and trading activities.

Jane Norman: Thank you. Good morning, and thank you for joining us for Amplitude Energy's FY 2026 full year results. This is Jane Norman, and I am joined today by Chief Financial Officer, Ian Bucknell, and Chief Operating Officer, Chad Wilson. Today's presentation and announcement were released to the ASX this morning and are available on the Amplitude Energy website. The webcast is being recorded and will be available on our website later today. Please note the disclaimer on slide 2 before moving to slide 3. I will start today by reflecting on our accomplishments through FY2026 before moving to an in-depth review of the financial year in the next section. FY2026 was another strong year of delivery for Amplitude Energy. We achieved record production and record financial results. Performance was supported by continued improvement at Orbost, resilient pricing from our contracted sales portfolio, and active gas marketing and trading activities.

Speaker #2: The webcast is being recorded and will be available on our website later today. Please note the disclaimer on slide two before moving to slide three.

Speaker #2: I'll start today by reflecting on our accomplishments through FY 26 before moving to an in depth review of the financial year in the next section , FY 26 was another strong year of delivery for Amplitude Energy .

Speaker #2: We achieved record production and record financial results. Performance was supported by continued improvement at Orbost, resilient pricing from our contracted sales portfolio, and active gas marketing and trading activities. Importantly, we also made substantial progress advancing the East Coast Supply Project, which remains a key driver of future growth.

Jane Norman: Importantly, we also made substantial progress advancing the East Coast Supply Project, which remains a key driver of future growth. The acquisition of a 50% interest in Artisan, alongside our existing Annie discovery, has further strengthened the resource base underpinning the project. At the same time, we acknowledge that our first exploration well, drilled earlier in FY2026, did not deliver the commercial outcomes we had hoped for. Geological success can never be guaranteed, and investment decisions are always made with the best information available at the time. Importantly, the exploration program was executed safely, on budget, and in accordance with industry best practice. Looking ahead, ECSP economics are underpinned by the Annie and Artisan discoveries. A comprehensive review of exploration results to date has reaffirmed the decision to drill Juliet for additional upside.

Speaker #2: The acquisition of a 50% interest in artisan alongside our existing anti discovery , has further strengthened the resource base underpinning the project At the same time , we acknowledge that our first exploration well drilled earlier in FY 26 , did not deliver the commercial outcomes we had hoped for Geological success can never be guaranteed and investment decisions are always made with the best information available at the time Importantly , the exploration program was executed safely on budget and in accordance with industry best practice Looking ahead , EXP economics are underpinned by the Annie and artisan discoveries .

Speaker #2: A comprehensive review of exploration results to date has reaffirmed the decision to drill Juliet for additional upside. We expect a final investment decision on the development phase of the project in the near term, with the project foundations strengthened and development planning well progressed.

Jane Norman: We expect a final investment decision on the development phase of the project in the near term. With the project foundation strengthened and development planning well progressed, we remain on track for first gas in 2028. Turning now to slide 4. The highlights on this page demonstrate the strength of our operations. Group production increased to a new record of 27.6 petajoules equivalent or 75.5 terajoules equivalent per day. This was towards the upper end of our production guidance range, which itself was upgraded earlier this calendar year. Sales revenue reached a new record of AUD 285.8 million. Despite increased market uncertainty, our average realized gas price increased to AUD 10.36 per gigajoule, while group unit production costs fell to a new record low of just above AUD 2 per gigajoule.

Speaker #2: We remain on track for first gas in 2028. Turning now to slide four, the highlights on this page demonstrate the strength of our operations group.

Speaker #2: Production increased to a new record of 27.6 petajoules equivalent, or 75.5 terajoules equivalent per day. This was towards the upper end of our production guidance range, which itself was upgraded earlier.

Speaker #2: This calendar year, sales revenue reached a new record of $285.8 million. Despite increased market uncertainty, our average gas price increased to $10.36 per gigajoule.

Speaker #2: While group unit production costs fell to a new record low of just above $2 per gigajoule, this resulted in underlying EBITDA increasing to approximately $191.8 million, with an underlying EBITDA margin of around 67%.

Jane Norman: This resulted in underlying EBITDA increasing to approximately AUD 191.8 million, with an underlying EBITDA margin of around 67%. Cash conversion was excellent, with adjusted cash from operations reaching AUD 191 million. These outcomes reflect the operating leverage in the business. Higher production, higher realized prices, and lower unit costs flowing through to stronger earnings and cash generation. With the base business humming, the focus in the immediate term turns to executing the next round of the ECSP drilling safely and on budget and schedule. In the last few days, we have received back the Transocean Equinox to commence the Juliet well, and we expect results by mid to late September. Success at Juliet will provide a further boost to already attractive project economics and resource life at our Otway assets.

Speaker #2: Cash conversion was excellent , with adjusted cash from operations reaching $191 million . These outcomes reflect the operating leverage in the business , higher production , higher realized prices , and lower unit costs flowing through to stronger earnings and cash generation .

Speaker #2: With the base business humming, the focus in the immediate term turns to executing the next round of the CSP drilling safely and on budget and schedule. In the last few days, we have received back the Transocean Equinox to commence the Juliet well, and we expect results by mid to late September. Success at Juliet will provide a further boost to already attractive project economics and resource life at our Otway assets.

Speaker #2: The next section of the presentation will speak to the operational and strategic highlights of FY 26 . First , before Ian covers the financial results and Chad provides more detail on the growth projects and the FY 27 outlook .

Jane Norman: The next section of the presentation will speak to the operational and strategic highlights of FY2026 first, before Ian covers the financial results and Chad provides more detail on the growth projects and the FY2027 outlook. I will start with operational details beginning on slide 6. Safety remains fundamental to how we operate. In FY2026, when more than half a million hours were worked across our activities, we recorded zero lost time injuries and zero medical treatment injuries. We have now gone more than 2 and a half years without a single LTI, while our total recordable injury frequency rate improved to 1.97, well below the industry benchmark. We also recorded no reportable environmental incidents during this period.

Speaker #2: I'll start with operational details, beginning on slide six. Safety remains fundamental to how we operate in FY26, where more than half a million hours were worked across our activities.

Speaker #2: We recorded zero lost time injuries and zero medical treatment injuries. We have now gone more than two and a half years without a single LTI, while our total recordable injury frequency rate improved to 1.97.

Speaker #2: Well below the industry benchmark . We also recorded no reportable environmental incidents during this period . This is a strong outcome given the scale of activity undertaken during the year , including the EXP drilling campaign , offshore maintenance work and a plan shutdown at the Athena gas plant .

Jane Norman: This is a strong outcome given the scale of activity undertaken during the year, including the ECSP drilling campaign, offshore maintenance work, and a planned shutdown at the Athena gas plant. We continue to progress our environmental commitments through operational flaring reduction initiatives, the Athena Solar PV project, and the voluntary offsetting of Scope 1 and Scope 2 emissions. Moving across to slide 7. Orbost continued to be the main driver of the company's production growth. Average production from Orbost increased to 66.5 terajoules per day in FY2026, and the plant is now operating above its previous nameplate capacity of 68 terajoules per day. The plant's performance reflects the success of the operational improvement program, with the sulfur removal system no longer acting as a regular production constraint that it once was.

Speaker #2: We continue to progress our environmental commitments through operational flaring reduction initiatives, the Athena Solar PV project, and the voluntary offsetting of Scope 1 and Scope 2 emissions.

Speaker #2: Moving across to slide seven . All this continued to be the main driver of the company's production growth . Average production from August increased to 66.5 Tera joules per day in FY 26 , and the plant is now operating above its previous nameplate capacity of 68 Terajoules per day .

Speaker #2: The plant's performance reflects the success of the operational improvement programme, with the sulphur removal system no longer acting as a regular production constraint as it once was.

Speaker #2: Absorber cleans reduced materially from 21 in FY 25 to just four in FY 26 , and production downtime also continued to decline , with the plant holding daily production records around 74 terajoules per day over the last six weeks .

Jane Norman: Absorber cleans reduced materially from 21 in FY2025 to just 4 in FY2026, and production downtime also continued to decline. With the plant holding daily production records around 74 terajoules per day over the last 6 weeks, the focus now turns to further reliability improvements and sustaining higher throughput. Importantly, the Sole reservoir continues to perform strongly to support these higher production rates. Please now move to slide 8. We completed important development work at both our Otway and Cooper Basin assets in the H2 of FY2026, which should provide production benefits into FY2027. In the Otway and offshore maintenance campaign, reestablished communication of the Casino-4 well, bringing it back into production and improving overall cycling of the Casino, Henry and Netherby fields. Since the Athena gas plant's planned maintenance in April, our 50% share of production has averaged 8.5 terajoules per day.

Speaker #2: The focus now turns to further reliability improvements and sustaining higher throughput. Importantly, the sole reservoir continues to perform strongly to support these higher production rates. Please now move to slide eight.

Speaker #2: We completed important development work at both our Otway and Cooper Basin assets in the second half of FY26, which should provide production benefits into FY27.

Speaker #2: In the Otway and Offshore Maintenance campaign, we re-established communication with the Casino-4 well, bringing it back into production and improving the overall cycling of the Casino.

Speaker #2: Henry and Netherby fields, since the Athena gas plant’s planned maintenance in April, are 50% share of production has averaged 8.5 terajoules per day. The plant also recorded excellent uptime over FY26, with reliability loss of just 0.7% of asset capacity in the Cooper Basin.

Jane Norman: The plant also recorded excellent uptime over FY2026, with reliability loss of just 0.7% of asset capacity. In the Cooper Basin, production was impacted by natural field decline and H1 flooding, but improved in the H2 as 3 new Cooralonga wells came online. These assets remain small contributors, but they provide valuable free cash flow and portfolio diversity. Now on to slide 9. At 30 June 2026, 2P reserves were 26.7 million barrels of oil equivalent or about 163 petajoules equivalent. The year-on-year movement is largely explained by FY2026 production, with no material reserves revisions. Contingent resources increased to 50.8 million barrels of oil equivalent, reflecting additional contingent resource potential at Sole, and a modest uplift associated with Patricia Baleen, partly offset by Otway permit relinquishments. These reserves and resource numbers do not include Artisan, as completion of that acquisition is yet to occur.

Speaker #2: Production was impacted by natural field . Field decline and first half flooding , but improved in the second half as three new Calabanga wells came online These assets remain small contributors , but they provide valuable free cash flow and portfolio diversity Now on to slide nine .

Speaker #2: As at the 30th of June 2026 , £0.02 reserves were 26.7 million barrels of oil equivalent , or about 163 Petajoules equivalent . The year on year movement is largely explained by FY 26 production , with no material reserves , revisions , contingent resources increased to 50.8 million barrels of oil equivalent , reflecting additional contingent resource potential at Sol and a modest uplift associated with Patricia Berlin .

Speaker #2: Partly offset by Otway permit . Relinquishments . These reserves and resource numbers do not include artisan as completion of that acquisition is yet to occur If we could go to slide ten , here , we show the latest picture of our existing gas contract stack alongside the Uncontracted or spot gas exposure for our equity share of total production on a calendar year basis As you can clearly see , our revenue base is made up of mainly fixed price CPI linked gas sales contracts .

Jane Norman: If we could go to slide 10. Here we show the latest picture of our existing gas contract stack, alongside the uncontracted or spot gas exposure for our equity share of total production on a calendar year basis. As you can clearly see, our revenue base is made up of mainly fixed price CPI-linked gas sales contracts. Around 80% of gas sales this calendar year are expected to be contracted under existing GSAs, providing a resilient revenue base while retaining exposure to higher value spot and recontracting opportunities. The weighted average contract price stepped up by around 20% from January 2026, reflecting annual indexation and the commencement of higher price contracts. We will continue to reshape existing arrangements where it makes good economic sense and retain some exposure to spot gas markets.

Speaker #2: Around 80% of gas sales this calendar year are expected to be contracted under existing GSAs, providing a resilient revenue base while retaining exposure to higher-value spot and recontracting opportunities.

Speaker #2: The weighted average contract price stepped up by around 20% from January 2026, reflecting annual indexation and the commencement of higher price contracts.

Speaker #2: We will continue to reshape existing arrangements where it makes good economic sense and retains some exposure to spot gas markets. As a reminder, this slide speaks to contracts over our existing production position and excludes volumes from the East Coast supply project. Let's move to slide 11.

Jane Norman: As a reminder, this slide speaks to contracts over our existing production position and excludes volumes from the East Coast Supply Project. Let's move to slide 11. The continuous improvement program remains central to how we run the business. In FY2026, around 70 initiatives were completed or in delivery, with approximately one-third realizing value during the year. In aggregate, the program delivered around AUD 13.4 million in annualized cash flow improvement in FY2026, taking cumulative annualized benefits from our improvement program since FY2024 to more than AUD 50 million. Most of the FY2026 value came from operational improvements at Orbost, including sulfur treatment and capacity improvements, reduced contractor and consumable costs, and optimization of operations. The program has also reinforced a leaner operating culture across the business, with the team continuing to identify value from production efficiency, waste disposal, maintenance planning, insurance, and corporate cost discipline.

Speaker #2: The continuous improvement program remains central to how we run the business in FY26. Around 70 initiatives were completed or are in delivery, with approximately one-third realizing value during the year.

Speaker #2: In aggregate, the program delivered around $13.4 million in annualized cash flow improvement in FY26, taking cumulative annualized benefits from our improvement program.

Speaker #2: Since FY 24 to more than $50 million . Most of the FY 26 value came from operational improvements at August , including sulphur treatment and capacity improvements , reduced contractor and consumable costs , and optimisation of operations The program has also reinforced a leaner operating culture across the business , with a team continuing to identify value from production efficiency , waste disposal , maintenance , planning , insurance and corporate cost discipline Our commercial team continues to pursue sources of value through spot gas trading and marketing initiatives over the financial year .

Jane Norman: Our commercial team continues to pursue sources of value through spot gas trading and marketing initiatives. Over the financial year, the team generated more than AUD 1.5 million in net revenue over and above the Victorian daily spot gas price by modifying the profile of sales to preference high gas prices, prioritizing sales into markets with the highest price, and realizing various other new trading initiatives. The focus in FY27 is on sustaining these gains while finding new wins on costs, production efficiency, and realized margin. In FY27, there will be a particular focus on streamlining systems with the replacement of our internal ERP system, which we expect will catalyze G&A savings in subsequent years. Turning now to slide 12, covering the growth potential across our portfolio. Our growth strategy remains centered on backfilling existing infrastructure.

Speaker #2: The team generated more than $1.5 billion million dollars in net revenue over and above the Victorian Delhi spot . Gas price . By modifying the profile of sales to preference high gas prices , prioritising sales into markets with the highest price and realizing various other new trading initiatives .

Speaker #2: The focus in FY 27 is on sustaining these gains . While finding new wins on costs , production efficiency and realized margin in FY 27 , there will be a particular focus on streamlining systems with the replacement of our internal ERP system , which we expect will catalyse G&A savings in subsequent years Turning now to slide 12 .

Speaker #2: Covering the growth potential across our portfolio. Our growth strategy remains centered on backfilling existing infrastructure at Athena. The EXP is designed to bring supply from new onshore Otway gas fields through the plant, extending its life and improving utilization and installed processing capacity in the Gippsland.

Jane Norman: At Athena, the ECSP is designed to bring supply from new onshore Otway gas fields through the plant, extending its life and improving utilization and install processing capacity. In the Gippsland, we are continuing to increase Orbost production through debottlenecking and reliability improvements while progressing the Patricia Baleen restart project. The chart on this slide illustrates that when these growth opportunities are brought together, by FY29, the company has the potential to roughly double the earnings we produced in FY26. We consider this to be very achievable, given it assumes ECSP production from only Annie and Artisan and the other internal mid-case assumptions, without factoring in further upside from exploration success at Juliet and potentially Nestor. This helps illustrate why the ECSP is so transformational for the company, and Chad will talk in more detail about these opportunities in the growth section.

Speaker #2: We are continuing to increase orbital production through debottlenecking and reliability improvements, while progressing the Patricia Bail Restart Project. The chart on this slide illustrates that, when these growth opportunities are brought together by FY29, the company has the potential to roughly double earnings.

Speaker #2: We produced in FY 26 . We consider this to be very achievable . Given it assumes EXP from only Annie and Artisan and the other internal mid case assumptions without factoring in further upside from exploration success at Juliet and potentially Nestor This helps illustrate why the exp is so transformational for the company and Chad will talk in more detail about these opportunities in the growth section Part of the reason we're so focused on the growth is the gas demand story , which I'll describe on page 13 .

Jane Norman: Part of the reason we are so focused on the growth is the gas demand story, which I'll describe on page 13. On the demand side, the role of gas is becoming more important as electricity generation systems change and demand grows. Electrification is occurring in many forms, from the uptake of electric vehicles to higher household electricity use, to the rollout of new technologies. Globally, data center electricity demand is expected to grow significantly as AI adoption increases, with large-scale data centers requiring reliable around-the-clock power. That is already influencing investment in conventional dispatchable sources of electricity internationally. In Australia, data centers are expected to contribute to renewed electricity demand growth at the same time as coal-fired generation retires. Renewables and batteries will be important contributors to supply, but gas remains the only currently available and scalable source of long-duration dispatchable electricity in Australia.

Speaker #2: On the demand side, the role of gas is becoming more important as electricity generation systems change and demand grows. Electrification is occurring in many forms, from the uptake of electric vehicles to higher household electricity use, to the rollout of new technologies globally.

Speaker #2: Data center electricity demand is expected to grow significantly as AI adoption increases , with large scale data centres requiring reliable around the clock power that is already influencing investment in conventional dispatchable sources of electricity .

Speaker #2: Internationally, in Australia, data centres are expected to contribute to renewed electricity demand growth, at the same time as coal-fired generation retires.

Speaker #2: Renewables and batteries will be important contributors to supply the gas remains the only currently available and scalable source of long duration , dispatchable electricity in Australia Batteries can help manage minutes and hours , but gas is needed to carry the system through longer periods when renewable output is low Domestic gas supply close to market , where it's consumed , is the best capable is best capable of providing this critical source of system firming Amplitude Energy is well positioned to respond to these market dynamics Southern Australia needs new local production to replace declining supply and reduced reliance on higher cost gas from further north , or potential LNG imports .

Jane Norman: Batteries can help manage minutes and hours, but gas is needed to carry the system through longer periods when renewable output is low. Domestic gas supply close to market where it's consumed is best capable of providing this critical source of system firming. Amplitude Energy is well-positioned to respond to these market dynamics. Southern Australia needs new local production to replace declining supply and reduce reliance on higher-cost gas from further north or potential LNG imports. Our portfolio is focused entirely on the domestic market, located close to the demand centers in Victoria and South Australia and connected to existing infrastructure. The ECSP is therefore more than just a growth project for Amplitude Energy. It has the potential to contribute meaningfully to energy security, reliability, and affordability in southeastern Australia.

Speaker #2: Our portfolio is focused entirely on the domestic market, located close to the demand centres in Victoria and South Australia, and connected to existing infrastructure.

Speaker #2: The EXP is, therefore, more than just a growth project for energy. It has the potential to contribute meaningfully to energy security, reliability, and affordability in South Australia.

Speaker #2: To get to this point on the EXP , we have invested years and tens of millions of dollars in the project . Navigating a complex and changing policy and approvals environment while doing so , there is clear scope for policy to be more supportive of domestic gas supply to deliver the lower cost gas that consumers want .

Jane Norman: To get to this point on the ECSP, we have invested years and tens of millions of AUD in the project, navigating a complex and changing policy and approvals environment while doing so. There is clear scope for policy to be more supportive of domestic gas supply to deliver the lower-cost gas that consumers want. We continue to engage closely with the federal government on the proposed Domestic Gas Reservation Scheme. Reform presents an opportunity to improve investment certainty to domestic gas projects through faster and more streamlined approvals, removal of duplicative regulation, and a more workable consultation framework for offshore exploration and development. These changes do not require government to subsidize projects. All that is required is for the regulatory settings to facilitate timely investment in supply that the market clearly needs.

Speaker #2: We continue to engage closely with the federal government on the proposed domestic gas reservation policy. This reform presents an opportunity to improve investment certainty for domestic gas projects through faster and more streamlined approvals.

Speaker #2: Removal of duplicative regulation and a more workable consultation framework for offshore exploration and development. These changes do not require government to subsidize projects.

Speaker #2: All that is required is for the regulatory settings to facilitate timely investment in supply that the market clearly needs. I will now hand over to Ian to cover off the FY26 financial highlights, starting on page 15.

Jane Norman: I will now hand over to Ian to cover off the FY2026 financial highlights, starting on page 15.

Jane Norman: I will now hand over to Ian to cover off the FY 2026 financial highlights, starting on page 15.

Speaker #3: Thanks , Jane , and good morning everyone FY 26 again demonstrates the operating leverage in the business before even considering the transformational growth potential of the East Coast supply project Looking at the charts , production has increased nicely over the past five years .

Ian Bucknell: Thanks, Jane, and good morning, everyone. FY2026 again demonstrates the operating leverage in the business before even considering the transformational growth potential of the East Coast Supply Project. Looking at the charts, production has increased nicely over the past five years while unit production costs have continued to fall. Underlying EBITDAX and adjusted cash from operations have both grown at around 24% compound annual growth since FY2022. This is the financial expression of what Jane described operationally. Higher production from existing infrastructure, disciplined cost control, and better realized pricing. The result is margin expansion and a much stronger cash generation platform. Our high cash flows and operating margins are, of course, what one should expect from a capital-intensive business with conventional offshore gas fields. Substantial upfront investment is needed to realize these resources. However, once production is online, ongoing costs are low, and the resulting cash returns are high.

Ian Bucknell: Thanks, Jane, and good morning, everyone. FY 2026 again demonstrates the operating leverage in the business before even considering the transformational growth potential of the East Coast Supply Project. Looking at the charts, production has increased nicely over the past five years while unit production costs have continued to fall. Underlying EBITDAX and adjusted cash from operations have both grown at around 24% compound annual growth since FY2022. This is the financial expression of what Jane described operationally. Higher production from existing infrastructure, disciplined cost control, and better realized pricing. The result is margin expansion and a much stronger cash generation platform. Our high cash flows and operating margins are, of course, what one should expect from a capital-intensive business with conventional offshore gas fields. Substantial upfront investment is needed to realize these resources. However, once production is online, ongoing costs are low, and the resulting cash returns are high.

Speaker #3: While unit production costs have continued to fall, underlying EBITDA and adjusted cash from operations have both grown at around 24% compound annual growth since FY22.

Speaker #3: This is the financial expression of what Jane described operationally higher production from existing infrastructure , disciplined cost control and better realised pricing . The result is margin expansion and a much stronger cash generation platform Our high cash flows and operating margins are , of course , what one should expect from a capital intensive business with conventional offshore gas fields Substantial upfront investment is needed to realise these resources .

Speaker #3: However , once production is online , ongoing costs are low and the resulting cash returns are high Moving now to slide 17 . Looking at the annual result in more detail , our financial results follow the excellent operational performance of the base business over FY 26 , with a 3% increase in production to 27.6 Petajoules equivalent for the year and a 5% rise in average realised prices , resulting in sales revenue increasing by 7% to $285.8 million .

Ian Bucknell: Moving now to slide 17, looking at the annual result in more detail. Our financial results followed the excellent operational performance of the base business over FY2026, with a 3% increase in production to 27.6 petajoules equivalent for the year, and a 5% rise in average realized prices. Resulting in sales revenue increasing by 7% to AUD 285.8 million. Production expenses fell to approximately AUD 57 million, with unit production costs falling to AUD 2.07 per gigajoule on a group basis. Specifically at Orbost, unit production costs were well below AUD 2 per gigajoule, significantly outperforming our internal target set at the start of FY2026. Unit production costs at Orbost in FY2026 were 33% below FY2024 levels, showing just how far the plant has come. Production costs and other expenses landed in line with guided expectations.

Speaker #3: Production expenses fell to approximately $57 million , with unit production costs falling to $2.07 per gigajoule . On a group basis , specifically at Orbost , unit production costs were well below $2 per gigajoule significantly outperforming our internal targets set at the start of FY 26 .

Speaker #3: Unit production costs at Orbost in FY 26 were 33% below FY 24 levels , showing just how far the plant has come . Production costs and other expenses landed in line with guided expectations .

Speaker #3: Followers of the company may recall, around $16 million in general visual inspection, or GVI, costs were allowed for at the Seoul and British Berlin pipelines in FY26.

Ian Bucknell: Followers of the company may recall around AUD 16 million in general visual inspection, or GVI costs, were allowed for at the Sole and Patricia Baleen pipelines in FY26. These inspections were completed in FY26, and pleasingly, the cost came in at less than half of the original AUD 16 million budget. Higher revenue and lower costs result in a 12% rise in underlying EBITDAX to AUD 191.8 million. The business generated AUD 180.3 million in operating cash flows or AUD 191 million in adjusted cash from operations once restoration and other irregular items are excluded. The strength of these cash flows provides us with comfort in funding the ECSP whilst maintaining a strong balance sheet. Our reported and underlying measures of profit and loss after tax were impacted by the circa AUD 100 million pre-write-off of the Isabella and Elanora exploration costs from earlier this calendar year.

Speaker #3: These inspections were completed in FY26, and pleasingly, the cost came in at less than half of the original $16 million budget.

Speaker #3: Higher revenue and lower costs resulted in a 12% rise in underlying EBITDAX to $191.8 million. The business generated $188.3 million in operating cash flows, or $191 million in adjusted cash from operations.

Speaker #3: Once restoration and other irregular items are excluded, the strength of these cash flows provides us with comfort in funding the EXP, whilst maintaining a strong balance sheet.

Speaker #3: Our reported and underlying measures of profit and loss after tax were impacted by the circa $100 million pre write off of the Isabella and Eleanora exploration costs from earlier this calendar year , CapEx came in a little under our guided range of 125 to $150 million , driven by strong project cost control and the phasing of expenditure on long lead items .

Ian Bucknell: CapEx came in a little under our guided range of AUD 125 to AUD 150 million, driven by strong project cost control and the phasing of expenditure on long lead items. Restoration payments were also significantly lower and not expected to be material in the near to medium term. Our net debt position as at 30 June was AUD 37.6 million, reflecting a strong balance sheet ahead of the ECSP investment phase. Net debt was reduced by over AUD 200 million over FY26 and is nearly AUD 250 million lower than its peak in late 2024. Since financial year-end, we have continued to build cash reserves as the next phase of ECSP drilling approaches. If we can now turn to slide 17. This EBITDAX bridge shows the drivers of the strong result.

Speaker #3: Restoration payments were also significantly lower, and not expected to be material in the near to medium term. Our net debt position as at 30 June was $37.6 million, reflecting a strong balance sheet ahead of the EXP investment phase.

Speaker #3: Net debt was reduced by over $200 million over FY 26 and is nearly $250 million lower than its peak in late 2024 . Since financial year end , we have continued to build cash reserves as the next phase of EXP drilling approaches .

Speaker #3: If we can now turn to slide 17, this EBITDAx bridge shows the drivers of the strong result. Higher gas sales volumes and higher realized gas prices were the largest positive contributors.

Ian Bucknell: Higher gas sales volumes and higher realized gas prices were the largest positive contributors, both driven by the continued improvement at Orbost and the step-up in contract pricing. Lower crude oil revenue from the Cooper Basin was a headwind, reflecting both lower oil production and flooding impacts earlier in the year. Cost of sales improved through better plant reliability, operating efficiencies, and reduced maintenance requirements at Orbost. Taken together, the bridge demonstrates that margin expansion was broad based with pricing, volume, and cost performance all contributing to the record result. We will now move to slide 18, and this cash bridge is equally important. Strong operating cash flows more than covered CapEx during the year, despite the step-up in ECSP expenditure. Cash at 30 June 2026 was approximately AUD 138 million, supported by operating cash generation and the equity raising completed during the year.

Speaker #3: Both driven by the continued improvement at Orbost and the step-up in contract pricing. Lower crude oil revenue from the Cooper Basin was a headwind, reflecting both lower oil production and flooding impacts earlier in the year.

Speaker #3: Cost of sales improved through better plant reliability , operating efficiencies and reduced maintenance requirements . At Orbost . Taken together , the bridge demonstrates that margin expansion was broad based , with pricing volume and cost performance all contributing to the record result .

Speaker #3: We'll now move to slide 18, and this cash bridge is equally important. Strong operating cash flows more than covered CapEx during the year.

Speaker #3: Despite the step-up in EXP expenditure, cash at 30th June 2026 was approximately $138 million, supported by operating cash generation and the equity raising completed during the year.

Speaker #3: Debt repayment reduced drawn debt , materially leaving net debt at around $38 million at year end . Whilst commenting on debt . It is worth noting that our reserve based loan , the RBL facility , provides significant continuing financing flexibility .

Ian Bucknell: Debt repayment reduced drawn debt materially, leaving net debt at around AUD 38 million at year-end. Whilst commenting on debt, it is worth noting that our reserve base loan, the RBL facility, provides significant continuing financing flexibility. At 30 June 2026, debt available under the RBL was AUD 480 million, with AUD 175 million drawn. Together with our cash on hand and an additional AUD 25 million working capital facility, this gives the company substantial available liquidity. Over time, we intend to optimize the borrowing base, including potentially incorporating ECSP discoveries where appropriate. The business enters FY27 with strong liquidity and a materially lower net debt position than at the peak of FY25. I will now hand to Chad to cover the growth project section starting on slide 20.

Speaker #3: As of 30 June 2026, the debt available under the RBL was $480 million, with $175 million drawn, together with our cash on hand and an additional $25 million working capital facility.

Speaker #3: This gives the company substantial available liquidity. Over time, we intend to optimize the borrowing base, including potentially incorporating E&P discoveries where appropriate.

Speaker #3: The business enters FY 27 with strong liquidity and a materially lower net debt position than at the peak of FY 25 . I'll now hand to Chad to cover the growth projects section , starting on slide 20 .

Speaker #4: Thanks , Ian . This slide provides an illustration of our strategy to grow production into the latent capacity of our existing assets in FY 26 , our group production on an equity share basis was around 75 Terajoules equivalent per day .

Chad Wilson: Thanks, Ian. This slide provides an illustration of our strategy to grow production into the latent capacity of our existing assets. In FY26, our group production on an equity share basis was around 75 terajoules equivalent per day. By 2028, the combination of the ECSP production through Athena and further optimization at Orbost has the potential to lift group production materially. The key point is that the growth is brownfield. It uses infrastructure we already own and operate, including the Athena and Orbost plants. That gives us a lower risk and faster pathway to new domestic gas supply than a greenfield development. The Athena plant will retain capacity for peak production or third-party tolling even after being backfilled with volumes from the East Coast Supply Project.

Speaker #4: By 2028, the combination of the EXP production through Athena and further optimisation at Orbost has the potential to lift group production materially.

Speaker #4: The key point is that the growth is brownfield. It uses infrastructure we already own and operate, including the Athena and Orbost plants.

Speaker #4: That gives us a lower risk and faster pathway to new domestic gas supply than a greenfield development. The Athena plant will retain capacity for peak production.

Speaker #4: Our third-party tolling, even after being backfilled with volumes from the East Coast Supply Project, remains valuable. The value of this available capacity is only likely to grow over time, as the shape of gas use changes and supply from legacy gas fields declines.

Chad Wilson: The value of this available capacity is only likely to grow over time as the shape of gas use changes and supply from legacy gas fields declines. On slide 21, I'll provide the latest on the ECSP. Over the weekend, we were pleased to welcome back the Transocean Equinox to commence the Juliet Exploration Campaign. I'll cover Juliet in detail on the next slide, but it remains a key source of upside potential for the ECSP. More broadly, the project remains on track for first gas in 2028. The economics are underpinned by discovered resources at Annie and Artisan. Beach Energy has completed and flow tested the Artisan well, meaning it's now ready for tie-in to the ECSP. We will assume operatorship of the field once the Artisan acquisition moves through its final regulatory approval steps over this financial year.

Speaker #4: On slide 21, I'll provide the latest on the EXP. Over the weekend, we were pleased to welcome back the Transocean Equinox.

Speaker #4: To commence the Juliet Exploration campaign, I'll cover Juliet in detail on the next slide, but it remains a key source of upside potential for the EXP more broadly. The project remains on track for first gas in 2028.

Speaker #4: The economics are underpinned by discovered resources at Annie and Artisan Beach has completed the completed and flow tested . The artisan well meaning it's now ready for tie in to the exp We will assume operatorship of the field once the artisan acquisition moves through its final regulatory approval steps .

Speaker #4: Over this financial year, customer support for the project is strong, with foundation contracts secured with Energy and AGL. Feed is complete, and the project is fully funded.

Chad Wilson: Customer support for the project is strong with foundation offtake contracts secured with EnergyAustralia and AGL. FEED is complete and the project is fully funded. We're now very close to locking in the final development phase contracts, at which point we will look to make the final investment decision for that phase of the project. When we put all those factors together, project return should comfortably exceed our internal investment hurdle rates based on our mid-case assumptions. Moving to Juliet now on slide 22. Juliet has the highest level of prospectivity of all our exploration targets in the ECSP campaign, closely followed by Nestor. Prospect has strong geophysical support, including a conformable amplitude shut off at the top of the Waarre C reservoir and a flat spot interpreted as a potential gas water contact.

Speaker #4: We are now very close to locking in the final development phase . Contracts , at which point we will look to make the final investment decision for the for that phase of the project .

Speaker #4: When we put all those factors together, project return should comfortably, comfortably exceed our internal investment hurdle rates based on our mid-case assumptions.

Speaker #4: Moving to Juliet now on Slide 22. Juliet has the highest level of prospectivity of all our exploration targets in the EXP campaign, closely followed by Nestor.

Speaker #4: The prospect has strong geophysical support, including a conformable amplitude shut-off at the top of the Warwick Reservoir and a flat spot interpreted as a potential gas-water contact.

Speaker #4: It is a simple structure , imaged on good quality 3D seismic with reservoir and seal elements supported by nearby fields and wells . The gross and net prospective resource range is shown on the slide Importantly , the location of lying directly underneath the existing pipeline means tie in costs posed to discovery are low , and the resource is there .

Chad Wilson: It is a simple structure imaged on good quality 3D seismic, with reservoir and seal elements supported by nearby fields and wells. The gross and net prospective resource range is shown on the slide. Importantly, the location of Juliet, lying directly underneath the existing CHN pipeline, means tie-in costs post discovery are low, and the resource is therefore highly economic to develop. This would make a great addition to the ECSP on top of the Artisan and Annie base. Moving to slide 23 on the upcoming ECSP CapEx profile. From the outset of the project, we have sought to carefully manage the risks and phasing of ECSP CapEx. Drilling and well completions will account for the majority of the FY27 ECSP CapEx, with the drilling phase expected to be completed over the remainder of the calendar year.

Speaker #4: Therefore , highly economic to develop . This would make a great addition to the exp . On top of the artisan and Annie base Moving to slide 23 on the upcoming CapEx profile From the outset of the project , we have sought to carefully manage the risks and phasing of EXP CapEx , drilling and well completions will account for the majority of the FY 27 EXP CapEx .

Speaker #4: With the drilling phase expected to be completed over the remainder of the calendar year, this means that by the end of this calendar year, Amplitude will no longer face risks associated with EXP drilling, and it will have completed the majority of total EXP capital expenditure.

Chad Wilson: This means that by the end of this calendar year, Amplitude will no longer face risks associated with ECSP drilling, and it will have completed the majority of total ECSP capital expenditure. Subsea and other development costs are already very well defined ahead of FID, with a meaningful proportion related to long lead equipment and the remainder related to the actual development activity in late calendar year 2027 and early 2028. The profile shown here is illustrative and may, of course, change depending on the exploration outcome at Juliet and potentially Nestor. The key takeaway is that in the next few months, we will have a high degree of certainty regarding ECSP CapEx through to 2028. The subsea component of ECSP represents only 30% of total project CapEx, and well over half of those costs are made up of fixed price contracts.

Speaker #4: Subsea and other development costs are already very well defined ahead of FID, with a meaningful proportion related to long lead equipment and the remainder related to the actual development activity in late calendar year 2027 and early 2028. The profile shown here is illustrative and may, of course, change depending on the exploration outcome.

Speaker #4: At Juliet, and potentially Nestor. But the key takeaway is that in the next few months, we'll have a high degree of certainty regarding expected CapEx through to 2028.

Speaker #4: The subsea component of EXP represents only 30% of total project CapEx, and well over half of those costs are made up of fixed-price contracts, with the base business more than capable of funding that CapEx over the next two years.

Chad Wilson: With the base business more than capable of funding that CapEx over the next two years, we gain flexibility to allocate capital to other priorities as well. That is a nice segue to the Patricia Baleen restart project shown on slide 24. The Patricia Baleen restart is complementary to our wider project activities and overall portfolio. It is wholly owned, already connected to Orbost, and offers a low-cost pathway to add production flexibility through existing infrastructure. The select phase is complete, and the project is progressing through FEED. The current focus is on the lowest cost restart option for the existing Patricia Baleen wells, where limited facility modification is required and the key work is focused offshore. The opportunity is attractive because it can add incremental production through infrastructure we already operate and can potentially utilize the same vessel that we can use for the subsea work on ECSP.

Speaker #4: We gain flexibility to allocate capital to other priorities as well. That's a nice segue to the Patricia Baleen Restart project, shown on slide 24.

Speaker #4: The Patricia Baleen restart is complementary to our wider project activities and overall portfolio . It is wholly owned , already connected to Orbost , and offers a low cost pathway to add production flexibility through existing infrastructure .

Speaker #4: The select phase is complete and the project is progressing through FEED. The current focus is on the lowest-cost restart option from the existing Patricia Baleen wells, where limited facility modification is required and the key work is focused offshore.

Speaker #4: The opportunity is attractive because it can add incremental production through infrastructure . We already operate and can potentially utilise the same vessel that we can use for the subsea work on exp , the strategic value is broader than near-term production , preserving infrastructure and optionality that can support future discoveries .

Chad Wilson: The strategic value is broader than near-term production, preserving infrastructure and optionality that can support future discoveries, field developments, and third-party processing opportunities in the Gippsland Basin, including Long Tom as a potential future backfill option. Handing back to Jane now to cover the final section of the presentation on slide 26.

Speaker #4: Field developments and third party processing opportunities in the Gippsland Basin , including long term as a potential future backfill option . Handing back to Jane Now to cover the final section of the presentation on slide 26 .

Speaker #2: Thanks , John . Slide 26 provides a summary of our market guidance for FY 27 , consistent with prior years . Today , we are providing guidance for production cash expense and CapEx .

Jane Norman: Thanks, Chad. Slide 26 provides a summary of our markets guidance for FY27. Consistent with prior years, today we are providing guidance for production, cash expense, and CapEx. FY27 group production guidance is 26.6 to 28.5 petajoules equivalent, which translates to roughly 73 to 78 terajoules equivalent per day across the group. This range reflects Orbost's ability to produce above 70 terajoules per day but also allows for periods of lower production, a planned maintenance shutdown in FY27, natural decline at CHN and PEL 92, and standard allowances for downtime across the group's assets. Production expenses in FY27 are expected to total between AUD 58 million and AUD 64 million, a slight increase on FY26, driven by a planned statutory shutdown at Orbost next year. We expect other cash expenses and cost of sales in FY26 of AUD 27 million to AUD 31 million.

Speaker #2: FY27 group production guidance is 26.6 to 28.5 equivalent, which translates to roughly 73 to 78 terajoules equivalent per day across the group.

Speaker #2: This range reflects Orbis' ability to produce above 70 terajoules per day, but also allows for periods of lower production. A planned maintenance shutdown is expected in FY27, as well as natural decline at Ken and Pel 92.

Speaker #2: And, with standard allowances for downtime across the group's assets, production expenses in FY27 are expected to total between $58 million and $64 million.

Speaker #2: A slight increase in FY26, driven by a planned statutory shutdown in August next year. We expect other cash expenses and cost of sales in FY26 and FY27 of $27 million to $31 million.

Speaker #2: This includes general and administrative care and maintenance royalties , selling , transport and tolling costs , and other cash . OpEx items . Note this 27 to $31 million figure now also includes expected selling and transport costs associated with accessing the Sydney Spot gas market .

Jane Norman: This includes general and administrative, care and maintenance, royalties, selling, transport, and tolling costs, and other cash OpEx items. Note this AUD 27 to AUD 31 million figure now also includes expected selling and transport costs associated with accessing the Sydney spot gas market. These costs were excluded from guidance in 2026. We are now regularly accessing the Sydney spot market if the premium to the Victorian prices is greater than the cost of our transport. As our production rates and spot gas sales volumes have become more predictable, we can forecast these trading costs with great precision. Significant non-regular items that we expect will impact our 2027 expenses, including an estimated AUD 5 million for Patricia Baleen well inspections, and AUD 6 to AUD 7 million to replace our internal ERP system over the next year.

Speaker #2: These costs were excluded from guidance in FY 26 . We are now regularly accessing the Sydney Spot market . If the premium to the Victorian prices is greater than the cost of a transport and as our production rates and spot gas sales volumes have become more predictable and therefore we can forecast these trading costs with greater precision Significant non-regular items that we expect will impact FY 27 expenses , including an estimated $5 million for Patricia Baleen Whale inspections and 6 to $7 million to replace our internal ERP system over the next year .

Speaker #2: The ERP replacement is part of our commitment to continuing to streamline our internal systems and processes, and to identify cost and process efficiencies for future years.

Jane Norman: The ERP replacement is part of our commitment to continuing to streamline our internal systems and processes, and to identify costs and process efficiencies for future years. 2026 capital expenditure guidance is AUD 250 to AUD 310 million, largely reflecting our share of the Juliet and Annie drilling costs, as well as long lead order costs for the development phase of the project, assuming FID in the near term. CapEx guidance includes appropriate waiting on weather and other activity allowances, and the range incorporates a substantial level of additional project contingency. The range excludes uncommitted Nestor drilling costs and the upfront consideration for the Artisan acquisition. I will wrap up with our 2027 priorities on slide 27. Our immediate priority is to complete the drilling phase of the ECSP on time and on budget over the next few months.

Speaker #2: FY26 capital expenditure guidance is $250 to $310 million, largely reflecting our share of the Juliet and Annie drilling costs, as well as long lead order costs for the development phase of the project.

Speaker #2: Assuming FID in the near term, CapEx guidance includes appropriate weighting on weather and other activity allowances, and the range incorporates a substantial level of additional project contingency.

Speaker #2: The range excludes uncommitted Nestor drilling costs and the upfront consideration for the Artisan acquisition. I'll wrap up with our FY27 priorities on slide 27.

Speaker #2: Our immediate priority is to complete the drilling phase of the ESP on time and on budget over the next few months. While that is happening, we intend to progress the ESP development phase to FID to maintain the timeline to first gas in calendar year 2028.

Jane Norman: While that is happening, we intend to progress the ECSP development phase to FID to maintain the timeline to first gas in calendar year 2028. Second, we will look to maximize asset utilization, optimizing Orbost production above 70 terajoules per day where market conditions support it, maintaining reliability loss below 1% across our operating plants, and progressing the Patricia Baleen restart project. Third, we will seek to further grow margins through gas marketing and trading initiatives, continued cost control, and organizational improvements. That brings me to the end of today's presentation. To summarize, we are pleased with our performance of our underlying business in 2026. We delivered strongly in areas within our control, achieved record operational and financial performance, strengthened the performance of our base business, and advanced our growth portfolio. The next few months will be an important period for the company, with multiple catalysts ahead of us.

Speaker #2: Second, we will look to maximize asset utilization, optimizing Orbis production above 70 terajoules per day when market conditions support it, maintaining reliability loss below 1% across our operated plants, and progressing the.

Speaker #2: Patricia, Berlin Restart Project. Third, we will seek to further grow margins through gas marketing and trading initiatives, as well as continued cost control and organizational improvements.

Speaker #2: That brings me to the end of today's presentation. To summarize, we are pleased with the performance of our underlying business in FY26.

Speaker #2: We delivered strongly in areas within our control, achieved record operational and financial performance, strengthened the performance of our base business, and advanced our growth portfolio.

Speaker #2: The next few months will be an important period for the company , with multiple catalysts ahead of us . The result of the Juliet well and a final investment decision on the development of both expected in the near term Together , these milestones have the potential to create a significant value and reinforce our position as a key supplier of domestic gas to south eastern Australia .

Jane Norman: The result of the Juliet well and a final investment decision on the development are both expected in the near term. Together, these milestones have the potential to create a significant value and reinforce our position as a key supplier of domestic gas to southeastern Australia. We enter 2027 with strong momentum and look forward to keeping shareholders updated on our progress throughout the year. Operator, we can now open the line for questions. Thank you.

Speaker #2: We enter FY27 with strong momentum and look forward to keeping shareholders updated on our progress throughout the year. Operator, we can now open the line for questions.

Speaker #2: Thank you .

Speaker #1: If you wish to ask a question, please press star followed by one on your telephone and wait for your name to be announced.

Operator 2: If you wish to ask a question, please press star followed by 1 on your telephone and wait for your name to be announced. That is star 1 if you wish to ask a question. Our first question comes from the line of Gordon Ramsay from RBC Capital Markets. Your line is open.

Operator: If you wish to ask a question, please press star followed by 1 on your telephone and wait for your name to be announced. That is star 1 if you wish to ask a question. Our first question comes from the line of Gordon Ramsay from RBC Capital Markets. Your line is open.

Speaker #1: That is star one . If you wish to ask a question . And our first question comes from the Gordon Ramsay , from RBC Capital Markets .

Speaker #1: Your line is open .

Speaker #5: Oh , thank you very much for the result today . Solid results . Just looking forward in terms of the drilling program , just trying to get my head around the decision on the optional Nestor .

Gordon Ramsay: Thank you very much for the result presentation today. Solid result. Just looking forward in terms of the drilling program, just trying to get my head around the decision on the optional Nestor Well. Is it just a black and white decision that for some reason Juliet doesn't come in, then you will drill Nestor. If Juliet comes in, then Nestor won't be drilled. Is it that simple, or am I misreading it.

Speaker #5: Well , is it just kind of a black and white decision ? If for some reason Juliet doesn't come in , then you will drill Nestor .

Speaker #5: But if Juliet comes in, then Nestor won't be drilled. Is it that simple, or am I misreading it?

Speaker #2: Hi , Gordon , thanks for the question . The a joint venture partner , Oge energy , wants to wait until we see the result of the Juliet .

Jane Norman: Hi, Gordon. Thanks for the question. Our joint venture partner, Origin Energy, wants to wait until we see the result of the Juliet well before making a decision. At that point, our board and also the OG board will make a decision around whether to progress Nestor. There has been significant investment in the Nestor asset. We have all the approvals in place and all the long lead items, and we have 1 remaining rig slot available on the Transocean Equinox, so we can proceed if that is approved.

Speaker #2: Well, before making a decision. So, at that point, our board and also the OGE board will make a decision around whether to progress.

Speaker #2: Nestor . There has been significant investment in the Nestor asset . We have all the approvals in place and all the long lead items , and we have one remaining rig slot available on the Transocean Equinox , so we can proceed if if that is approved

Speaker #5: Okay . And then just on exploration expense , looking at underlying npat , clearly you haven't expensed your exploration there and it's in the statutory loss .

Gordon Ramsay: Okay. Just on exploration expense, looking at underlying NPAT, clearly you haven't expensed your exploration there and it's in the statutory loss. Just want to make sure that we understand the policy going forward on exploration expense in terms of how that's going to be treated. Maybe a question for Ian.

Speaker #5: I just want to make sure we understand the policy going forward on exploration expense, in terms of how that's going to be treated.

Speaker #5: Maybe a question for Ian.

Ian Bucknell: Yeah. Thanks, Gordon. Obviously, the last time since we drilled was 2019. We saw this as a one-off lumpy piece, so to carry it below the line, we want to highlight the progress in our underlying business for that. As you know, with these offshore drilling campaigns, they are lumpy. So yeah, we've taken that decision.

Speaker #3: Yeah , thanks , Gordon . Yeah , I mean , obviously the last time since we drilled was 2019 , we saw this as a as sort of a one off lumpy piece .

Speaker #3: And so to carry it below the line , we want to highlight the progress in underlying business . For that . So as you know , with these offshore drilling campaigns , they are lumpy .

Speaker #3: And so, yeah, we've taken that decision.

Speaker #5: Okay, thanks very much. And great result with Orbost. Thanks for your time.

Gordon Ramsay: Okay. Thanks very much, and great result with Orbost. Thanks for your time.

Speaker #3: Thanks .

Ian Bucknell: Thanks.

Speaker #1: Your next question comes from the line of Nick Burns from Jarden, Australia. Your line is open.

Operator 2: Your next question comes from the line of Nik Burns from Jarden Australia. Your line is open.

Operator: Your next question comes from the line of Nik Burns from Jarden Australia. Your line is open.

Speaker #6: Hi . It's hi everyone Jane , just maybe a follow up on Gordon's question in relation to Nestor . You talked about your recent engagement with the federal government in relation to their proposed domestic gas reservation scheme .

Nik Burns: Hi, everyone. Jane, just maybe a follow-up on Gordon's question in relation to Nestor. You talked about your recent engagement with the federal government in relation to their proposed Domestic Gas Reservation Scheme. How do you weigh up the commitment to a new well versus waiting for certainty or clarity around how this new policy may impact prices and therefore the economics of the well? Is there a scenario here where you don't commit to Nestor even if you maybe wanted to or irrespective of the success or otherwise at the prior well? Thank you.

Speaker #6: How do you weigh up the commitment to a new well versus waiting for certainty or clarity around how this new policy may impact prices and, therefore, the economics of the operation?

Speaker #6: Well , is there a scenario here where you don't commit to Nestor , or even a . You maybe wanted to or depending , irrespective of the success or otherwise , at the prior .

Speaker #6: Well , thank you .

Speaker #2: Yeah . Thanks , Nick . So look , today , the contracted position is 80% across the portfolio . And looking at the Annie and artisan base for the project , we're around 80% contracted with the Energy Australia and AGL GSA's place .

Jane Norman: Yeah. Thanks, Nik. So look, today the contracted position is 80% across the portfolio. Looking at the Annie and Artisan base for the project, we are around 80% contracted with the EnergyAustralia and AGL GSAs in place. That gives us a lot of confidence to move forward with the project. But we also know our big gentailer customers need more gas in southern markets, and we know that all of them are very frustrated by this reservation policy because ultimately it just pushes back investment and reduces investment confidence as they want to see gas delivered in these markets. They want diversity of delivery point, diversity of supplier, and they are very unlikely to rely on one pipeline from Queensland to deliver their gas. So we know there is appetite there. We also know the Athena plant has capacity of around 150 terajoules a day.

Speaker #2: That gives us a lot of confidence to move forward with the project . But we also know our big , gentler customers need more gas in southern markets , and we know that they are both all of them very frustrated by this reservation policy because ultimately it just pushes , pushes back investment and reduces investment confidence .

Speaker #2: And they want to see gas delivered in these markets. They want diversity of delivery point, diversity of supplier. And they're very unlikely to rely on one pipeline from Queensland to deliver their gas.

Speaker #2: So, we know there's appetite there. And we also know that the Athena plant has a capacity of around 150 terajoules a day. Each of the upstream wells is going to have deliverability of around 60 terajoules a day.

Jane Norman: Each of the upstream wells is going to have deliverability of around 60 terajoules a day. So we are choking the wells back to create the plateau that customers want. But we know that ultimately we have the upstream deliverability to hit that 150 TJ a day production rate. So something like Nestor would give us a lot of flexibility to run the plant up to 150, and we see there is demand in the market for peak products, peak demand, peak gas supply to meet that demand from electricity generation. So we think it is a really interesting opportunity. We remain really confident in the demand from our gentailer customers. They are not the group who are driving the noise behind this reservation policy. That is definitely the manufacturers. And what we are hearing in Canberra in the last couple of weeks is more positive.

Speaker #2: So we're choking the wells back to create the plateau that customers want. But we know that ultimately we have the upstream deliverability to hit that 150 TJ-a-day production rate.

Speaker #2: So something like Nestor would give us a lot of flexibility to run the plant up to 150. And we see this demand in the market for peak products, peak demand, peak gas supply to meet that demand from electricity generation.

Speaker #2: So, we think it's a really interesting opportunity. We remain really confident in the demand from our Gen customers. They're not the group who are driving.

Speaker #2: You know , the noise behind this reservation policy . That's definitely the manufacturers . So and what we're hearing in Canberra in the last couple of weeks is more positive .

Speaker #2: They've well and truly heard the feedback from the industry—that what was drafted is really unworkable, and that ultimately they would reduce investment and leave the country exposed to LNG imports down the track.

Jane Norman: They have well and truly heard the feedback from the industry that what was drafted is really unworkable, and that ultimately they would reduce investment and leave the country exposed to LNG imports down the track. So, we are expecting something in the form of an exposure draft or consultation in the second half of September, and so hopefully that is a more balanced approach.

Speaker #2: So we're expecting something in the form of an exposure draft or consultation in the second half of September. And so hopefully that's a more balanced approach.

Speaker #6: That's great . Thanks for that , Jane . And just on your contingent resource booking at Sol , your reserves report talked about the need to potentially drill another well to access that that gas .

Nik Burns: That is great. Thanks for that, Jane. Just on your contingent resource booking at Sole, your reserves report talked about the need to potentially drill another well to access that gas. Is there any plans or any thoughts around going after that additional volume?

Speaker #6: Are there any plans or any thoughts around going after that additional volume?

Speaker #2: I had a chat .

Jane Norman: I'll hand it to Chad.

Speaker #4: Yeah . Thanks , Nick . At this time . Yeah . We we booked it as contingent so that we could leave it there as the future opportunity .

Chad Wilson: Yeah. Thanks, Nik. At this time, we booked it as contingent so that we could leave it there as the future opportunity. It'll all come down to gas prices and what it'll cost us to drill that well when we have a rig in the area. Right now, I wouldn't say there's firm plans. It's a potential plan for the future.

Speaker #4: It'll all come down to gas prices and what it will cost us to drill that—well, when we have a rig in the area.

Speaker #4: So right now, I wouldn't say there's firm plans. It's a potential plan for the future.

Speaker #6: Got it. And just quickly on the Athena, there was a mention in there about maybe spending money to relight the plant.

Nik Burns: Got it. And just quickly on the Athena. There was a mention in there about maybe spending money on re-lifing the plant. Can you just talk about what's involved with that? Thanks.

Speaker #6: Can you just talk about what's involved with that? Thanks.

Speaker #4: Yeah . So for Athena relighting , there was a few things that we had to do . One was we have to do an intelligent pig run of the of the pipeline in the into Athena .

Chad Wilson: Yeah, so for Athena re-lifing, there was a few things that we had to do. One was we have to do an intelligent pig run of the pipeline into Athena, so that's more on the pipeline side. We have to replace the gas-to-gas exchanger bundle. As we've come down in volume there, we've had to plug tubes just to keep the velocity up through the gas-to-gas exchanger so that we have to replace that. And then there's really just a few other minor controls upgrades that are required. So in general, pretty minor work at the Athena plant.

Speaker #4: So that's more on the pipeline side . We have to replace the gas to gas exchanger bundle . As we've come down in volume there , we've had to plug tubes just to keep the velocity up through the gas to gas exchanger so that we have to replace that .

Speaker #4: And then there are really just a few other minor controls and upgrades that are required. So, in general, pretty minor work.

Speaker #4: At the Athena plant

Speaker #6: Got it. I might leave it there. Thank you.

Nik Burns: Got it. I might leave it there. Thank you.

Speaker #1: Your next question comes from the line of Declan Bonnick from Eurus. Hartley, your line is open. Declan, your line is open. As a reminder, if you wish to ask a question, please press star followed by one on your telephone. Your next question comes from the line of James Bullen from KGF.

Operator 2: Your next question comes the line of Declan Bolick from Euroz Hartleys. Your line is open. Declan, your line is open. As a reminder, if you wish to ask a question, please press star followed by one on your telephone. Your next question comes to line of James Bullen from CGF. Your line is open.

Operator: Your next question comes the line of Declan Bonnick from Euroz Hartleys. Your line is open. Declan, your line is open. As a reminder, if you wish to ask a question, please press star followed by one on your telephone. Your next question comes to line of James Bullen from CGF. Your line is open.

Speaker #1: Your line is open

Speaker #7: Jane and team, just a quick question around the Artisan acquisition. I mean, it's not normal that you see an acquisition of this scale occur during a period of regulatory uncertainty.

James Bullen: Jane and team, just a quick question around the Artisan acquisition. I mean, it is not normal that you see an acquisition of this scale occur during a period of regulatory uncertainty. Understand that you are pretty heavily contracted for ECSP, but is there anything in there that could prevent the completion happening if something in Canberra does go awry around the Domestic Gas Reservation Scheme, or is there any scope to renegotiate any of the terms if there was to be substantial regulatory change?

Speaker #7: I understand that you are pretty heavily contracted for EC and GSP, but is there anything in there that could prevent the completion from happening?

Speaker #7: If something in Canberra does go awry around the domestic gas reservation, is there any scope to renegotiate any of the terms?

Speaker #7: If there were to be substantial regulatory change,

Jane Norman: Yeah. Hi, James. Thanks for the question. Look, I think the approvals for this transaction are hopefully pretty straightforward. We are thinking we will get something end of this year or start of calendar year 2027, and hopefully the transaction will be finalized then. This is a really attractive acquisition for us. It leverages off the existing program. It leverages all the activity. We are able to add the umbilical flow lines to our long lead orders with the same delivery dates. So it is a significant cost advantage to add Artisan into our program versus the organic option that Beach Energy has. So, we remain really confident in it. It also helps us with blending away the Annie CO2 levels. So that removes the need for Amine at our plant. Obviously, we still need to see whether Juliet and/or Nestor is successful and what the composition of that gas is.

Speaker #2: Hi , Jim , thanks for the question . Look , I think the approvals for this transaction are hopefully pretty straightforward . We're thinking we'll get something end of this year or start of calendar year 27 .

Speaker #2: And hopefully, as the transaction will be finalized, this is a really attractive acquisition for us. It leverages off the existing program.

Speaker #2: It leverages all the activity. We’re able to add the umbilical and flowlines to our long lead orders with the same delivery dates.

Speaker #2: So, it's a significant cost advantage to add Artisan into our program versus the organic option that Beech has. So we remain really confident in it.

Speaker #2: It also helps us with blending away the CO2 levels . And so that removes the need for a man at our plant . Obviously , we still need to see whether Juliet and or Nestor are successful and what the composition of that gas is .

Speaker #2: But on any artisan basis, it gives us confidence that we won't need a man at the plant. So it won't be affected by the domestic gas reservation.

Jane Norman: So on an anti-acid gas basis, it gives us confidence that we won't need Amine at the plant. It won't be affected by the Domestic Gas Reservation Scheme. As I talked about earlier, we remain really confident in the appetite and pricing from our gentailer customers. The two existing Gas Sales Agreements we have in place are at very attractive pricing that support the project economics, and we know that those customers need more gas in southern markets.

Speaker #2: And as I talked about earlier, we remain really confident in the appetite and pricing from our gentler customers. The two existing gas sales agreements we have in place are at very attractive pricing that support the project economics, and we know that those customers need more gas in southern markets.

Speaker #7: Okay . Thank you

James Bullen: Okay, thank you.

Speaker #1: As a reminder, please press star one to ask a question. Your next question comes from the line of Stuart Hall from Bell Potter Securities.

Operator 2: As a reminder, please press star one to ask a question. Your next question comes to the line of Stuart Howe from Bell Potter Securities. Your line is open.

Operator: As a reminder, please press star one to ask a question. Your next question comes to the line of Stuart Howe from Bell Potter Securities. Your line is open.

Speaker #1: Your line is open .

Speaker #7: Oh, hi, John.

Stuart Howe: Oh, hi, Jane and Shane. Just a couple of quick questions. Firstly, on guidance for FY27, you note a statutory shutdown at Orbost in H2. Just wondering if you could dial in a bit more on how many days that will be down.

Speaker #8: Just a couple of quick questions . Firstly on on guidance for FY 27 . You note a statutory shutdown at Orbost in the second half .

Speaker #8: Just wondering if you could dial in a bit more on how many days that will be down.

Speaker #4: Yeah, thanks, Stewart. Right now, the plan is for ten.

Chad Wilson: Yeah. Thanks, Stuart. Right now, the plan is for 10.

Speaker #8: And then just just on the nest . All decision to the extent that that is geology related around results or otherwise . Juliet obviously targeting the we sea sands as well as , you know , the unsuccessful .

Stuart Howe: Okay. Just on the Elanora decision. To the extent that that is geology related around results or otherwise at Juliet, obviously targeting the Waarre C sands as well as the unsuccessful well at Isabella. Can you talk to how much of that piece of that decision is the geology versus, I guess, the overall budget?

Speaker #8: Well at Isabella can you talk to , you know , how much of that piece of that decision is , is the geology versus , I guess the overall budget

Speaker #4: Yep . So just touching on that , it actually isn't the geology . We're we're pretty happy with that . It's an independent from the other other wells there .

Chad Wilson: Yeah. Just touching on that, it actually isn't the geology. We're pretty happy with that, and it's independent from the other wells. Obviously, the success of Juliet does support it, as they're so close that you can just over the statistical regime of the basin, it increases the statistical odds from things like your migration pathway and stuff for your gas. But the reality is, it comes more to the costs. Like Jane said, we have our joint venture partner. They've invested a lot in exploration throughout this past calendar year, and they really were looking to see some results out of the program before making a decision.

Speaker #4: Obviously, the success of Juliet does support it, as they're so close that you can just go over the statistical regime of the basin.

Speaker #4: It increases the statistical odds from things like your migration pathway and such for your gas. But the reality is, it comes more to the costs and the like.

Speaker #4: Jane said , we have our joint venture partner . They've invested a lot in in exploration throughout this past calendar year . And they they really were looking to see some results out of the program before making the decision

Speaker #8: Right. Thanks. That's really helpful.

Stuart Howe: Right. Thanks. That's really helpful.

Speaker #1: Your next question comes from line of Nick Burns from Jordan , Australia . Your line is open .

Operator 2: Your next question comes to line of Nik Burns from Jarden Australia. Your line is open.

Operator: Your next question comes to line of Nik Burns from Jarden Australia. Your line is open.

Speaker #6: Oh , thanks for the follow up . Just on Patricia Berlin . Just looking at the scope and I'm just trying to get my mind around what cost might be incurred to restart the field .

Nik Burns: Oh, thanks for the follow-up. Just on Patricia Baleen, just looking at the scopes. I am just trying to get my mind around what costs might be incurred to restart the field. Chad, you talked about utilizing the rig that we back to tie in the fields in the Otway. It does not sound like there is much of an incremental cost there, but maybe if you can try and quantify that would be helpful. Thank you.

Speaker #6: You talked about Chad. You talked about utilizing the rig. That will be back to tie in the fields on the Otway.

Speaker #6: So, it doesn't sound like there's much of an incremental cost there. But maybe if you can try and quantify that, that'd be helpful.

Speaker #6: Thank you

Speaker #4: Yeah . Thanks . So the cost is actually in two parts . So the first part , which would be at the same time that we're running the umbilical and flow lines for exp .

Chad Wilson: Yeah. Thanks. The cost is actually in two parts. The first part, which would be at the same time that we are running the umbilicals and flow lines for ECSP, there is the offshore component, where we actually have to pick up the umbilical that is there, cut out the UTA that was causing the problem, and replacing it. Then the second part of the cost would be sometime in the future, where we would have to do some plant modification work to get it through the low-pressure side of the plant. Patricia Baleen, for the first 18 months or so, will be able to flow through the high-pressure side of the plant on its own at a higher rate than we would produce longer term. That longer-term production, we have talked about being in that 4 to 5 terajoules a day range. That is the longer-term part.

Speaker #4: There's the offshore component, where we actually have to pick up the umbilical that's there, and cut out the UTA that was causing the problem.

Speaker #4: And replacing it. And then the second part of the cost would be sometime in the future, where we would have to do some plant modification work to get it through the low-pressure side of the plant.

Speaker #4: So Patricia Baleen , for the first 18 months or so , we'll be able to flow through the high pressure side of the plant on its own at a higher rate than than we would produce longer term .

Speaker #4: So that longer term production , we've talked about being in that 4 to 5 terajoules a day kind of range . That's the longer term part .

Speaker #4: So, the cost is split. No, it's about 60% of the cost for the line that's on the subsea element in 2028.

Chad Wilson: The cost is split. It is about 60% of the cost for Patricia Baleen is on the sub-sea element in 2028, and then about 30% for the plant costs, about 18 months later.

Speaker #4: And then about 30% for the plant costs, about 18 months later.

Speaker #6: Right . And a slide 24 talked about SDH participating in the select phase around long term potential connection . How would how do you contemplate the restart of long time and how that would interact or potentially interfere with production volumes out of Patricia Berlin and or Seoul ?

Nik Burns: Right. Slide 24 talked about SGH participating in the select phase around Long Tom potential connection. How do you contemplate the restart of Long Tom and how that would interact or potentially interfere with production volumes out of Patricia Baleen or Sole? Thanks.

Speaker #6: Thanks .

Speaker #4: Yeah . So they would . Long term plans would be to to produce after Seoul is completed , production

Chad Wilson: Yeah. Long Tom's plans would be to produce after Sole is completed production.

Nik Burns: Got it. Okay, great.

Speaker #6: Right . And

Speaker #2: The technical service work we did with Seven Group looked at a number of options, and PB restart alone was the most economic of those.

Jane Norman: The technical service work we did with Seven Group looked at a number of options, and PB restart alone was the most economic of those, so we are going to move ahead with that. Obviously, this project is very attractive economics because so much infrastructure already exists, and it is really just a matter of repairing the umbilical and the low-pressure part of the plant, as Chad talked about. This project is economic for as long as Sole produces. Obviously, the sooner we get it online, the more attractive it is. Then subject to plant availability and Long Tom achieving all of its approvals, there is an option there for them to produce into the plant. Equally, we will be looking at backfill options when Sole depletes and backfilling the plant ourselves.

Speaker #2: So we're going to move ahead with that. And obviously, this project is very attractive economically because so much infrastructure already exists.

Speaker #2: And it's really just a matter of repairing the umbilical and the low pressure plant of the part of the plant . As Chad talked about .

Speaker #2: But this project is economic for as long as Seoul produces . So , you know , obviously the sooner we get it online , the more attractive it is .

Speaker #2: And then subject to plant availability and and long term achieving all of its approvals , then there's an option there for them to produce into the plant .

Speaker #2: But equally, you know, we'll be looking at backfill options when Seoul depletes and backfilling the plant ourselves.

Speaker #6: That's great . Thanks for that . Maybe just one more just on slide 20 , you talked about the illustrative 2028 potential production .

Nik Burns: That is great. Thanks for that. Maybe just one more. Just on slide 20, you talked about the illustrative 2028 potential production. Just looking at the Sole bar there, you have got Sole debottlenecking on there in the green. I am just wondering, is that what has already been delivered now? Like, maximum rate of just under 75 terajoules a day? Or is there more to give or to extract from the current plant configurations prior to Patricia Baleen restart? Or is it very much as you said, Jane, it is about just trying to maximize uptime from here?

Speaker #6: Just looking at the the Seoul bar there , you've got Seoul Debottlenecking on there in the green . I'm just wondering , is that what's already been delivered now , like , you know , maximum rate of just under 75 Terajoules a day or .

Speaker #6: Yeah . Is there more to give or to extract from the current plant configuration prior to Patricia Berlin restart , or is it very much , as you said , Jane , it's about just trying to maximize uptime from here

Speaker #4: Yeah , that's that's exactly it . So the sole is the the bars across you can see are the same . The debottlenecking is about what we've done so far and how we get more out of that Debottlenecking is just continuing to improve the uptime .

Ian Bucknell: Yeah, that is exactly it. The Sole is the bars across, you can see are the same. The debottlenecking is about what we have done so far. And how we get more out of that debottlenecking is just continuing to improve the uptime. And then, yeah, the Patricia Baleen restart is the extra to take it to around that 80.

Chad Wilson: Yeah, that is exactly it. The Sole is the bars across, you can see are the same. The debottlenecking is about what we have done so far. And how we get more out of that debottlenecking is just continuing to improve the uptime. And then, yeah, the Patricia Baleen restart is the extra to take it to around that 80.

Speaker #4: And then, yeah, the Patricia restart is the extra to take it to around that 80.

Speaker #6: That's great. Thanks, Chad.

Nik Burns: That is great. Thanks, Chad.

Speaker #1: Your next question comes from Declan Hartley with Euros. Declan, your line is open.

Operator 2: Your next question comes line of Declan Bolick from Euroz Hartleys. Your line is open.

Operator: Your next question comes line of Declan Bonnick from Euroz Hartleys. Your line is open.

Speaker #9: Good morning. Can you hear me this time?

Declan Bolick: Good morning. Can you hear me this time?

Declan Bonnick: Good morning. Can you hear me this time?

Speaker #4: Yep .

Ian Bucknell: Yep.

Speaker #10: Yes .

Operator 2: Yes.

Jane Norman: Yes.

Speaker #9: Excellent . Thanks , Chad . So the disclosure on the restoration expenses over the next five years was interesting . Good disclosure . There .

Declan Bolick: Oh, excellent. Thanks, Jane, Ian, Chad. The disclosure on the restoration expenses over the next 5 years was interesting. Good disclosure there. When the ECSP is online, you should be generating a significant cash build. How are you and the board thinking about longer-term opportunities today?

Declan Bonnick: Oh, excellent. Thanks, Jane, Ian, Chad. The disclosure on the restoration expenses over the next 5 years was interesting. Good disclosure there. When the ECSP is online, you should be generating a significant cash build. How are you and the board thinking about longer-term opportunities today?

Speaker #9: So when the ESP is online, you should be generating a significant cash bill. How are you and the board thinking about longer-term opportunities today?

Speaker #3: Sorry, I just meant longer-term opportunities around restoration, or sorry—

Ian Bucknell: Sorry, just longer-term opportunities around restoration? Sorry.

Speaker #9: With that significant cash build . Obviously the restoration expenses have come down . You , you know , the exp should be delivered .

Declan Bolick: With that significant cash build, obviously the restoration expenses have come down. The ECSP should be delivered. How are you thinking about the longer-term opportunities with that cash?

Declan Bonnick: With that significant cash build, obviously the restoration expenses have come down. The ECSP should be delivered. How are you thinking about the longer-term opportunities with that cash?

Speaker #9: How are you thinking about the longer-term opportunities with that cash?

Speaker #3: For growth ? So yeah , it's a good point . Obviously we're in a year of record expenditure with exp . And as that cash comes at us , we will look at a usual sort of capital management plan where we'll try to balance forward growth opportunities and then and then we'll be looking at opportunities to return capital to shareholders through a number of means

Ian Bucknell: Oh, for growth. Yeah, it's a good point. Obviously, we're in a year of record expenditure, with ECSP. As that cash comes at us, we will look at a usual sort of capital management plan where we'll try to balance forward growth opportunities, and then we'll be looking at opportunities to return capital to shareholders through a number of means.

Speaker #9: Excellent. Interesting to hear. Thanks.

Declan Bolick: Excellent. Interesting to hear. Thanks, Ian.

Declan Bonnick: Excellent. Interesting to hear. Thanks, Ian.

Operator 2: There are no further questions. That does conclude our conference for today. Thank you for participating. You may now all disconnect.

Operator: There are no further questions. That does conclude our conference for today. Thank you for participating. You may now all disconnect.

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